1. Field of the Invention
This invention relates to a method of stimulating or increasing the rate of fluid flow into or out of a well. In another aspect this invention relates to a method of perforating a well wherein the formation around the perforations is fractured and the fractures thereby formed are propagated by high pressure injection of one or more fluids.
2. Description of Related Art
Well stimulation refers to a variety of techniques used for increasing the rate at which fluids flow out of or into a well at a fixed pressure difference. For production wells, it is important to increase the rate such that production of the well is more economically attractive. For injection wells, it is often important to increase the rate of injection at the limited pressure for which the well tubular equipment is designed.
The region of the earth formation very near the wellbore is very often the most important restriction to flow into or out of a well, because the fluid velocity is greatest in this region and because the permeability of the rock is damaged by drilling and completion processes. It is particularly important to find means for decreasing the resistance to flow through this zone.
Processes which are normally used for decreasing the fluid flow resistance near a wellbore are of two types. In one type, fluids such as acids or other chemicals are injected into a formation at low rates and interact with the rock matrix to increase permeability of the rock. In another type, fluid pressure is increased to a value above the earth stress in the formation of interest and the formation rock fractures. Injection of fluid at a pressure above the earth stress then is used to propagate the fracture away from the wellbore, in a process called hydraulic fracturing. Solid particles, called proppant, are added to the fracturing fluid to maintain a low resistance to fluid flow in the fracture formed by hydraulic fracturing after injection of fluid ceases and the fracture closes. Alternatively, if the formation contains significant amounts of carbonate rock, an acid solution not containing proppant is injected at fracturing pressures to propagate the fracture, in a process called acid fracturing. In some wells, where large increases in production rate are desirable, very large quantities of fluids are injected and a hydraulic fracture may be propagated for hundreds of feet away from a wellbore. In many cases, however, large fractures are not needed and a less expensive fracture extending a few feet or a few tens of feet will overcome the high resistance to fluid flow near the well and will be highly successful economically.
The pressures required to create and to maintain open a hydraulic fracture in the earth vary with depth and location in the earth. The fracture gradient, defined as downhole treating pressure required at the formation to maintain a fracture divided by depth of the formation, varies from about 0.5 psi per foot to about 1.0 psi per foot, but more commonly is in the range from about 0.65 to about 0.8 psi per foot. The fracture gradient is usually measured during fracturing treatments of wells by measuring the bottom-hole pressure instantaneously after pumping of fluids has stopped and before the fracture closes. The fracture gradient in a formation of interest will be known for an area where wells have been fractured. An initial breakdown pressure higher than predicted from the fracture gradient is often required to initiate a hydraulic fracture in a well. At least part of the reason for the breakdown pressure being higher than the pressure to maintain a fracture is the necessity to overcome tensile strength of the rock to initiate the fracture. The breakdown pressure is observed to vary from 0 to about 0.25 psi per foot greater than predicted from the fracture gradient. Therefore, to initiate a fracture around a well, pressures in the range from about 0.5 psi per foot of depth to about 1.25 psi per foot of depth are required.
The effectiveness of fracturing or other well stimulation methods in decreasing flow resistance near a well is often measured by "skin factor." Skin factors are measured by measuring bottom-hole pressures in a well under differing flow conditions. A positive skin factor indicates that the region around the wellbore is more resistive to flow than the formation farther away from the well. Likewise, a negative skin factor indicates that the near wellbore region has been made less resistive to flow than the formation. This lower resistance can be a result of a fracture or fractures created near the well and intersecting the wellbore or of changes in rock permeability near the wellbore.
A variety of methods have been proposed to create relatively short fractures to decrease near wellbore resistance to flow. Of course, the obvious method is to perform a conventional hydraulic fracturing treatment but pump less quantities of fluid and proppant. This method is widely practiced, often under the name "minifrac." Unfortunately, the cost of assembling the equipment for such small jobs limits the usefulness of the minifrac. Other processes have been proposed. U.S. Pat. No. 4,633,951 discloses use of combustion gas generating units and a cased wellbore filled with compressible hydraulic fracturing fluid, such as foam, the fracturing fluid containing proppant particles. The pressure of the compressible fluid is increased to a pressure in excess of the fracturing pressure of the formation--sometimes far in excess. The casing of the wellbore is then perforated to release the compressible fluid and particles through the perforations at high pressures. The fractures formed are sanded off until the perforations become plugged with proppant particles. U.S. Pat. No. 4,718,493, a continuation-in-part of the '951 patent, discloses continued injection of the compressible fracturing fluid after perforating the casing until fluid leak-off causes proppant to plug the fracture back to the wellbore. Proppant at moderate to high concentrations in the fracturing fluid is proposed.
U.S. Pat. No. 3,170,517 discloses a method of creating a relatively small hydraulic fracture from a wellbore by placing a fracturing fluid, which may be an acid or may contain proppant, in a well, building up gas pressure above the fracturing fluid, and perforating the casing of the well. Fracturing pressure of the formation is applied from the gas only until the gas pressure is depleted by flow from the wellbore.
Most wells for hydrocarbon production contain steel casing which traverses the formation to be produced. The well is completed by perforating this casing. Three types of perforating equipment are commonly used: (1) shaped charge, (2) bullet, and (3) high-pressure jets of fluid. The shaped-charge gun is by far the most common. The perforation formed must penetrate the steel casing and preferably will penetrate the zone of damaged permeability which often extends for a few inches around a wellbore as a result of processes occurring during drilling of the hole. The most common method of placing perforating apparatus in a well is attaching it to an electrically conducting cable, called an "electric wire line." This type perforating gun can be run through tubing in a well to perforate casing below the tubing; larger diameter guns can be run in casing only. In recent times, a method of perforating called "tubing-conveyed perforating" has been developed. In this method, apparatus is attached to the bottom of the tubing before it is run into a well and the firing of the charges is initiated by dropping of a bar down through the tubing or by a pressure-activated firing device. Vent valves, automatic dropping of the gun from the bottom of the tubing after firing and other features can be used along with tubing-conveyed perforating.
The use of high pressure gas in a wellbore to clean perforations has been described. In the paper "The Multiwell Experiment--A Field Laboratory in Tight Gas Sandstone Reservoirs," J. Pet. Tech. June, 1990, p. 775, the authors describe perforating a zone while the casing was pressurized with nitrogen gas to around 3,000 psi above the formation fracturing stress to achieve excellent communication with the formation, believed to be the result of cleaning the perforations with the high pressure nitrogen and preventing contact of the formation by liquids. Also, the paper "Hydraulic Fracturing in Tight, Fissured Media," J. Pet. Tech., Feb.,1991, p. 151, describes procedures for perforating in high-pressure nitrogen gas.
To increase the effectiveness of fracturing or any other stimulation method, it is important to treat all existing the perforations A variety of "diversion" techniques are used in an effort to insure that fracturing fluid or other stimulation fluid enters all open perforations. Such methods as pumping "ball sealers," pumping gel diverting slugs and pumping oil-soluble resin particles, sized salt, benzoic acid flakes and other sized particles into perforations are commonly used. But all these methods are very limited in their capabilities to divert fluids to every existing perforation.
While there have been a variety of methods proposed for creating small hydraulic fractures and for cleaning perforations around a wellbore, there has remained the long-felt need for an economical method which creates a pattern of high-pressure fractures emanating from all the perforations into a formation, allows for extensive cleaning of the perforations and near-wellbore region around the well and allows for placing a controlled amount of proppant in the pattern of fractures created.